1. Field of the Invention
The present invention pertains to methods and apparatus for installing and suspending tubing in an oil and/or gas well. More specifically, the present invention pertains to methods and apparatus for installing and suspending coiled tubing and associated apparatus in an oil and/or gas well.
2. Description of the Prior Art
In the drilling and completion of an oil and/or gas well, a hole is drilled through the earth to a subterranean formation which comprises a reservoir for oil and/or gas. Typically, the drilled hole is lined with a string of pipe, sometimes referred to as a "casing string", and one or more smaller diameter strings of pipe are lowered therein and supported at the surface of the well by a wellhead. The smaller diameter pipe, sometimes referred to as "tubing", is the pipe through which the oil and/or gas typically rises to the surface of the well, by natural pressures or by pumping, for production. The tubing string may also be used to run safety valves, packers, plugs and other apparatus into the well.
Typically, such tubing is manufactured in rigid joints of 40 to 80 foot sections. The joints must be transported to the well, stored on a pipe rack and vertically positioned in a derrick or the like before installation in the well. Then they are threadedly connected, joint by joint, as the string is lowered into the well. If it becomes necessary to reposition or remove the tubing, it must be disconnected, joint by joint, and removed from the well. Obviously, these procedures are labor and time intensive, resulting in relatively expensive operations.
In recent years, coiled tubing has been developed and used in the oil field as an alternative to conventional jointed tubing. Coiled tubing offers many advantages over conventional jointed tubing, including time and labor savings, pumping flexibility, elimination of leakage and leak testings, reduced formation damage, safety, etc. The coiled tubing may range in sizes from 3/4" OD up to 3 1/2" OD. The operational concept of a coiled tubing system involves running a continuous string of small diameter tubing into a well to perform specific well servicing operations without disturbing existing completion tubulars and equipment. When servicing is complete, the small diameter tubing and servicing equipment may be retrieved from the well and the coiled tubing spooled onto a large reel for transport to and from work locations.
Although coiled tubing has been in use since the early 1960's, it's use in production applications has only begun to gain widespread acceptance in the last few years. Producers have for several years successfully used concentric coiled tubing inside larger conventional tubing to enable the wells to continuously unload liquids. For example, coiled tubing has been used to jet sludge from wells as deep as 20,000 feet prior to hanging the string off and then unloading water through the "siphon" tubing to increase gas production. In the past few years, coiled tubing has begun to gain acceptance as a primary production string. Coiled tubing can be run in underbalanced well conditions to minimize formation damage from completion of workover operations. Installation and removal are generally faster than with jointed pipe. Joint connections are reduced or eliminated, minimizing potential for leaks and the need for testing connections. Cost is competitive with jointed pipe in most sizes. Coiled tubing is compatible with most artificial lift methods.
The typical procedure for hanging coiled tubing from the surface as a production or an injection string may include the following steps:
1. Rigging up a coiled tubing unit and killing the well if necessary.
2. Installing a coiled tubing head. This may already be in place or may be in addition to existing wellhead equipment. Many times the tubing head will be installed on the lower master valve.
3. Nippling up or installing blowout preventers (BOP's) on the tubing head. This usually also includes, above the blowout preventers, an access window assembly.
4. Running coiled tubing with a shear out or pump out bottom plug on the lower end to prevent possible well flow back through the coiled tubing. The BOP's may be used for annular well control.
5. When the end of the coiled tubing reaches the desired depth, the lower set of BOP's are closed and the tubing is checked for leaks.
6. The distance from the bottom flange of the access window assembly to tubing head lock screws is measured to insure that the annular hanger assembly sets completely in its hanger profile.
7. A wrap around style annular hanger assembly (with slips and seals) is placed around the coiled tubing and slowly lowered to the top of the lower set of blowout preventer rams.
8. The upper blowout preventers are closed and the lower blowout preventers are opened, allowing pressure to equalize across the spool.
9. The hanger assembly is lowered to the depth of a hanger bowl and the weight of the tubing is landed on the hanger. Lock down screws are engaged and the hanger's seals are pressure tested.
10. The coiled tubing is rough cut through the window of the access window assembly and the blowout preventers and access window assembly are removed.
11. A final or smooth cut is made on the coiled tubing and it is beveled to fit an adapter and to avoid damaging adapter seals. The remaining wellhead equipment is then installed and flow lines connected.
12. The coiled tubing is pressured up to shear out the bottom plug.
13. The well is placed in service.
In the typical coiled tubing installation of the prior art just described, it is, as indicated, necessary to provide an access window assembly above the blowout preventers to provide access to the coiled tubing and the annular space surrounding the coiled tubing in the tubing head. It is necessary to open the access window assembly for placement of the hanger assembly around the coiled tubing so that it may be lowered into the tubing head. Even though pressure control may be maintained by blowout preventers, this potentially opens the annular space surrounding the coiled tubing to pressure in the well. As is well known in the industry, an oil and/or gas well that is not under total pressure control can result in dangerous situations. The fact that the hanger assembly must be lowered around the coiled tubing from a point near the bottom of the access window assembly to the seating area in the tubing head, without being seen, also provides a potential for improper seating of the hanger seal and actuation of it's slips. Wrap-around slip and sealing assemblies of such hangers are inherently more likely to create sealing or slip engagement problems.
Even though coiled tubing installations, particularly production applications thereof, have become widely accepted in the last few years, apparatus and methods for completing and producing wells with coiled tubing continue to be developed. For example, the method and apparatus of co-pending application Ser. No. 08/308,407 provides substantial improvements for installing coiled tubing in an oil and/or gas well, particularly for production of hydrocarbon fluids therefrom. It provides a tubing head and hanger which, unlike the prior art, is designed so that the tubing unit stripper or blowout preventers do not have to be disconnected to hang the coiled tubing string in the well. Furthermore, all components of the hanger apparatus are internal, eliminating the need to install access window assemblies to set the tubing in the hanger and thus eliminating the pressure control problems associated with such.
The hanger apparatus of Ser. No. 08/308,407 includes a tubing head, having a vertical flow passage therethrough, for surmounting on the wellhead of the well. An annular sealing assembly is carried in a counterbored portion of the flow passage and a slip assembly is carried in a second counterbored portion above the first mentioned counterbored portion. The sealing and slip assemblies make up the hanger assembly. Also carried by the tubing head are slip activation devices which engage the slip assembly within the second counterbored portion of the flow passage and which are manipulatable externally of the tubing head to move the slip assembly from passive positions to active positions.
In the method of installing coiled tubing with the apparatus of Ser. No. 08/308,407, the coiled tubing hanger apparatus, which includes the tubing head, annular seal assembly and slip assembly are all installed on the wellhead, completely assembled, prior to lowering the coiled tubing into the well. A blowout preventer stack and the coiled tubing injector apparatus are installed thereabove. The coiled tubing is run through the blowout preventer stack and the coiled tubing head until the string of coiled tubing reaches its desired depth in the well. This is done while the slip assembly is in an expanded passive position. After the coiled tubing has reached the proper depth, the slip assembly is activated externally of the tubing head, the slips thereof moving to a contracted active position grippingly engaging a portion of the coiled tubing which it surrounds. Then the coiled tubing is slightly lowered to allow the weight of the tubing string to be totally supported by the slip assembly, the weight of the coiled tubing also expanding the sealing assembly to seal around the coiled tubing. After the coiled tubing is so hung and sealed, it is cut off at a point above the hanger apparatus, the injection apparatus and the blowout preventer stack are removed and remaining wellhead equipment installed.
Thus, the apparatus and method of Ser. No. 08/308,407 allows the use of coiled tubing for production applications without having to disconnect the tubing injector apparatus or blowout preventers and without having to use an access window assembly. There is complete pressure control of the well at all times. The internal slip and seal assemblies are contained within the coiled tubing head but are activated externally thereof. Furthermore, the slip assembly may be moved or retracted to an inactive or passive position to allow the coiled tubing to be repositioned, lower or higher in the well, without pulling the tubing.
While the apparatus of Ser. No. 08/308,407 is a substantial improvement over the prior art, particularly in production applications, the related sealing and slip assemblies may not provide enough clearance to allow lowering of packers, safety valves or other tools through the tubing head. There are many situations in which it would be desirable to use such equipment while providing the other advantages of coiled tubing.